A number of operations in a wellbore use balls, plugs, or the like to actuate downhole tools, close off fluid flow, and perform other operations. For example, bridge plugs used in plug and perforation operations for completing a wellbore may have balls disposed therein to control fluid flow or may have balls dropped to engage the plugs during fracture operations.
In a staged fracturing operation, multiple zones of a formation may be isolated sequentially for treatment using dropped balls. To achieve this, operators install a fracturing assembly down the wellbore, which typically has a top liner packer, open hole packers isolating the wellbore into zones, various sliding sleeves, and a wellbore isolation valve. When the zones do not need to be closed after opening, operators may use single shot sliding sleeves for the fracturing treatment. These types of sleeves are usually ball-actuated and lock open once actuated. Another type of sleeve is also ball-actuated, but can be shifted closed after opening.
Initially, operators run the fracturing assembly in the wellbore with all of the sliding sleeves closed and with the wellbore isolation valve open. Operators then deploy a setting ball to close the wellbore isolation valve. This seals off the tubing string of the assembly so the packers can be hydraulically set. At this point, operators rig up fracturing surface equipment and pump fluid down the wellbore to open a pressure-actuated toe sleeve so a first zone can be treated.
As the operation continues, operators drop successively larger balls down the tubing string and pump fluid to treat the separate zones in stages. When a dropped ball meets its matching seat in a sliding sleeve, the pumped fluid forced against the seated ball shifts the sleeve open. In turn, the seated ball diverts the pumped fluid into the adjacent zone and prevents the fluid from passing to lower zones. By dropping successively increasing sized balls to actuate corresponding sleeves, operators can accurately treat each zone up the wellbore.
As background to the present disclosure, FIG. 1A shows an example of a sliding sleeve 10 for a multi-zone fracturing system in partial cross-section during an opened state, and FIG. 1B illustrates a close up view of the sliding sleeve 10. This sliding sleeve 10 is similar to Weatherford's ZoneSelect MultiShift fracturing sliding sleeve and can be placed between isolation packers in a multi-zone completion. The sliding sleeve 10 includes a housing 20 defining a bore 25 and having upper and lower subs 22 and 24. An inner sleeve or insert 30 can be moved within the housing's bore 25 to open or close fluid flow through the housing's flow ports 26 based on the inner sleeve 30′s position.
When initially run downhole, the inner sleeve 30 positions in the housing 20 in a closed state. A breakable retainer 38 initially holds the inner sleeve 30 toward the upper sub 22, and a locking ring or dog 36 on the sleeve 30 fits into an annular slot within the housing 20. Outer seals on the inner sleeve 30 engage the housing 20′s inner wall above and below the flow ports 26 to seal them off.
The inner sleeve 30 defines a bore 35 having a seat 40 fixed therein. To open the sliding sleeve 10 in a fracturing operation, operators drop an appropriately sized ball B downhole and pump the ball B until it reaches the seat 40 disposed in the inner sleeve 30.
Once the ball B is seated, built up pressure forces against the inner sleeve 30 in the housing 20, shearing the breakable retainer 38 and freeing the lock ring or dog 36 from the housing's annular slot so the inner sleeve 30 can slide downward. As it slides, the inner sleeve 30 uncovers the flow ports 26 so flow can be diverted to the surrounding formation. The shear values required to open the sliding sleeves 10 can range generally from 1,000 to 4,000 psi (6.9 to 27.6 MPa).
Once the sleeve 10 is open, operators can then pump proppant at high pressure down the tubing string to the open sleeve 10. The proppant and high pressure fluid flows out of the open flow ports 26 as the seated ball B prevents fluid and proppant from communicating further down the tubing string. The pressures used in the fracturing operation can reach as high as 15,000-psi.
After the fracturing job, the well is typically flowed clean, and the ball B is floated to the surface. In some cases, the ball B cannot be floated to the surface because the ball has become wedged in the seat or for some other reason. In any event, the ball seat 40 (and the ball B if remaining) is milled out in a milling operation. The ball seat 40 can be constructed from cast iron to facilitate milling, and the ball B can be composed of aluminum or a non-metallic material, such as a composite. Once milling is complete, the inner sleeve 30 can be closed or opened with a standard “B” shifting tool on the tool profiles 32 and 34 in the inner sleeve 30 so the sliding sleeve 10 can then function like any conventional sliding sleeve that shifts with a “B” tool.
To reduce the need to mill out the balls B, various materials and designs have been used to make the balls disintegrate, dissolve, break apart, or otherwise degrade in the wellbore. Being able to degrade the balls B eliminates the need to flow the balls B back to surface after the fracture operation and reduces the complexity of milling operations for any balls B not floated to the surface. Degradable balls and other plugs find uses in applications other than just sliding sleeves.
A number of materials and designs have been developed to disintegrate, dissolve, break apart, or otherwise degrade balls in a wellbore environment when exposed to certain factors, such as temperatures, pressures, fracture fluids, other pumped fluids, hydrocarbons, time spans, etc. Examples of such materials and designs are disclosed in US 2012/0181032; US 2012/0273229; US 2011/0132621; U.S. Pat. Nos. 8,528,633; 8,403,037; 8,127,856; and U.S. Pat. No. 7,350,582.
The materials and designs condense down to two particular approaches. In the first approach, the structure of the ball is compromised externally when subjected to the wellbore environment. For example, U.S. Pat. No. 8,528,633 discloses a ball having perforations in its outer surface. The perforations control a rate of intrusion of the wellbore environment into the ball and below its outer surface. By controlling this rate of intrusion, the rate of reaction of the ball's material with the environment can be controlled so that the ball is weakened to a point where it can fail due to the stress applied to it.
In another example, US 2011/0132621 discloses a ball having two or more parts that are resistant to dissolution, but are bound together by an adherent material that can dissolve. During use, dissolution of the adherent material allows the two or more parts of the ball to move out of engagement with a ball seat so that the parts pass through the seat.
In the second approach, the material of the ball is compromised externally when subjected to the wellbore environment. For example, US 2012/0273229 discloses a composite downhole article (e.g., ball) having a corrodible core that corrodes at a faster rate in wellbore fluid than the rate that an outer member disposed on the core corrodes. An access point on the outer member can provide access of wellbore fluid to the corrodible core. In another example, US 2012/0181032 discloses a ball composed of a material that disintegrates, dissolves, delaminates, or otherwise experiences a significant degradation of its physical properties over time in the presence of hydrocarbons and formation heat.
As can be seen, both of these approaches subject the ball to the wellbore environment to initiate the degradation externally. Although these approaches may be effective, the need to maintain the structural integrity of the ball during use is a driving consideration for operators. As the industry progresses, higher pressures are being used downhole, and more and more zones are being treated downhole in a given wellbore. To operate properly, a composite ball needs to withstand high fracture pressures and needs to maintain its shape engaging a seat under such pressures. The ball may also need to function properly for longer periods of time. If the ball deforms or fails, then the fluid seal it provides with the seat will be compromised and make the fracture treatment ineffective. In light of this, the tolerances and size differences between deployed balls is becoming smaller and requiring more precision. Existing technology for manufacturing balls is approaching pressure and temperature limitations beyond which the deployed balls become less effective. In addition to fracture balls, other plugs used in other application preferably maintain their integrity while being degradable in a given application.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.